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February 2, 2013

VIA FEDERAL EXPRESS (CONFIDENTIAL BUSINESS INFORMATION REDACTED VERSION)

The Hon. Lisa Jackson

Administrator U.S. Environmental Protection Agency USEPA Ariel Rios Building (AR) 1200 Pennsylvania Avenue N.W. Washington, DC 20004

Re: Request for Administrati ve Reconsideration and Stay BART for Units 2 and 3, Apache Generating Station 77 Fed. Reg. 72512 (Dec. 5, 2012)

Dear Ms. Jackson:

On December 5, 2012, the U.S. Environmental Protection Agency ("EPA”) promulgated the final rule “Approval, Disa pproval and Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze State and Fede ral Implementation Plans” in the Federal Register at volume 77, pages 72512 and following (the “Rule”). As part of the Rule, EPA promulgated a Federal Implementation Plan (“FIP”) establis hing “best available retrofit technology” or “BART” for Apache Generating Station Steam Un its 2 and 3 operated by the Arizona Electric Power Cooperative, Inc. (“AEPCO”). AEPC O respectfully petitions for administrative

reconsideration under the Administrativ e Procedures Act, 5 U.S.C. § 501 et seq. (“APA”), and Clean Air Act, 42 U.S.C. § 7401 et seq. (“CAA”), and further requests a stay of the effective and compliance dates pending EPA’s action on this pe tition. The reasons for AEPCO’s petition and request for stay are set forth below.

Background

AEPCO is a rural, consumer-owned genera tion and transmission electric cooperative formed in 1961 to provide electric generation serv ice to local rural, c onsumer-owned electric distribution cooperatives in Ariz ona. As a not-for-profit cooper ative, AEPCO is fully owned by

its members. AEPCO has six “Class A” memb ers, who participate in and rely on AEPCO’s electric generation services, a nd one “Class D” member that only participates in AEPCO’s electric scheduling and trading services. Together, AEPCO’s Cl ass A members serve just underPetition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 2

150,000 meters. The electric service base is heavil y skewed toward rural residential use, with relatively little commerci al or industrial load.

Because of the rural and residential nature of the cooperatives it serves and which comprise its membership, AEPCO is a relativel y small entity with limited financial means. AEPCO operates only one power generation faci lity: the Apache Generating Station. Apache

was first constructed with the installation of Steam Unit 1 (“ST1”), a 72 net MW steam unit in 1963 and Gas Turbine 1 (GT1), a 10 net MW simp le cycle gas turbine in 1964. GT1 exhausts through either the ST1 windbox and stack or it s own stack. In 1978-197 9, AEPCO added Steam Units 2 and 3 (“ST2” and “ST3”), almost identica l Riley Stoker turbocharged boiler units with a 175 net MW capacity each. ST2 and ST3 are AE PCO’s coal-fired units. A number of other simple cycle combustion turbines (GT2 through GT 4) were added later. Collectively, Apache has approximately 555 MW of net installed capacity. As EPA noted in the Rule, AEPCO and its members sold less than 2.5 million MWh of electricity in 2011, well below the 4 million MWh or 750 MW net used by the Federal Energy Re gulatory Commission (“FERC”) to classify a utility as small. 77 Fed. Reg at 72540; 13 C.F.R. § 121.201 n.1.

AEPCO’s small generating capability results in a correspondingly limited financial base

and financial resources. AEPCO has patronage capital—essentially earnings contributed by its members and legally required to be returned to them in the future—of approximately $103

million. AEPCO’s total revenues for the last th ree years ranged from $209 million in 2008 to $169 million in 2011. Under the terms of the coope rative’s bylaws, all amounts in excess of operating costs, expenses and prior losses are re ceived with the understanding that they are furnished by the members as patronage capital and eventually returned back to the members. Att. A, AEPCO Bylaws, § 7.02. In addition, AEPC O has approximately $189 million in debt, secured by a mortgage with the Rural Utilities Service (“RUS”) and National Rural Utilities Cooperative Finance Corporation (“CFC”). The RUS mortgage limits AEPCO’s total debt to $600 million, assuming AEPCO can get necessary approval or lien accommodation under RUS regulatory and loan processes to fund capital add itions. Unlike many other electric cooperatives, AEPCO is also subject to re gulation by its state public utility commission, the Arizona Corporation Commission (“ACC”). The ACC must approve AE PCO’s rates to its Arizona members and also AEPCO’s debt arrangements. For the reasons discussed in this petition,

AEPCO does not believe that it can afford to expand its debt to the extent necessary to accommodate the FIP’s imposition of selective cata lytic reduction and the SIP’s requirement for scrubber upgrades on ST2 and ST3.

Arizona’s Regional Haze and BART SIP and EPA’s BART FIP

Arizona was a member of the Grand Canyon Visibility Transport Commission and has the option of submitting a regional haze SIP pur suant to either 40 C.F.R. §§ 51.308 (a “Section 308 SIP”) or 51.309 (a “Section 309 SIP”). The Ar izona Department of Environmental Quality (“ADEQ”) timely submitted a Section 309 SIP on December 23, 2003 and submitted a correction adding smoke management rules and updating st atutes on December 31, 2004. EPA approved the smoke management rules, but did not take any other action on this submittal by ADEQ.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 3

On October 13, 2006, EPA revised its rules and required states to submit revised Section 309 SIP by December 17, 2007. On January 15, 2009, EPA found that Arizona had failed to make all or part of required Section 309 SI P submittals. ADEQ subsequently submitted a Section 308 SIP on February 28, 2011. This Sect ion 308 SIP submittal was deemed complete by operation of law on August 28, 2011.

On July 20, 2012, EPA published a Federal Register notice of its intent to approve in part and disapprove in part the Section 308 SIP a nd to promulgate a FIP to establish BART requirements for three coal-fired utility plan ts, including AEPCO’s Apache Generating Station. AEPCO, the Arizona Utilities Group (“AUG”), and the National Rural Electric Cooperative Association (“NRECA”) filed comments, as di d ADEQ. AEPCO is a member of both AUG and NRECA and adopted their comments in addition to submitting its own comments.

On December 5, 2012, EPA promulgated its final approval in part and disapproval in part

of the Arizona Section 308 SIP establishing PM and SO 2 BART and promulgated a FIP establishing additional NOx BART requirement s for AEPCO’s Apache Generating Station. See 77 Fed. Reg. 72512 (Dec. 5, 2012). EPA’s BART FI P reflected its judgment that low NOx burners plus overfire air plus selective catalytic re duction (LNB + OFA + SCR or collectively “SCR”) were achievable and cost effective and therefore required as BART. In light of AEPCO’s small entity status, EPA did reduce th e stringency of the proposed SCR limit from 0.05 lb/mmBtu 30-day rolling average per unit to 0.07 lb/mmBtu 30-day rolling average over both ST2 and ST3. AEPCO’s petition for administra tive reconsideration is due within 60 days of publication in the Federal Register and is timely submitted.

AEPCO’s Petition for Administra tive Reconsideration and Stay

AEPCO respectfully requests that the Administrator undertake administrative

reconsideration of the BART FI P pursuant to the APA and CAA. AEPCO specifically requests administrative reconsideration of three aspects of the BART FIP: (1) EPA’s determination that LNB+OFA+SCR is not “unaffordable” for AEPCO; (2) EPA’s apparent inclusion of the simple cycle gas turbine operation of GT1 in the ST1 BA RT determination; and (3) EPA’s BART limit averaging provisions, which may inadvertently pr eclude restart and proper maintenance of the units. The bases for AEPCO’s request are set forth more fully below.

I. EPA Should Reconsider Its Determination that LNB + OFA + SCR Is “Affordable” for AEPCO in Light of the Total Costs of the Regional Haze SIP and FIP.

In its comments on the draft FIP, AEPC O advised EPA that, based on the best information available at that time, the pr oposed SCR systems on ST2 and ST3 would be unaffordable and likely would require that the units be shut down. EP A frankly acknowledgedPetition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 4

that it did not have the expertise to address this issue. 1 Instead, it relied on its contractor, EC/R, its subcontractor, Energy Strategies, LLC , and upon a report submitted by EarthJustice’s

consultant Paul Chernick with Resource Insi ght. This reliance was and remains misplaced.

A. EPA’s BART Determination Fundamental ly Misunderstands the Relation of Cooperative Members to AEPCO.

1. AEPCO’s Members Are Independent Entities that Make Power and Energy Purchase Decisions Based on the Best Interest of Their

Members

In its analysis, EPA and its contractor, EC/R, and subcontractor, Energy Strategies, assume that AEPCO’s existing membership base will remain with the cooperative. 77 Fed. Reg.

at 72541 & Table 6. This reflects a fundament al misunderstanding of the relationship of

AEPCO’s members with AEPCO and with each other.

Each AEPCO member is a cooperative charge d with procuring econom ical power for its members. Because the members are independent le gal entities, they have the ability to deal on the market for that power. The three smallest members are “all requirements members,” or ARMs, who have contracted with AEPCO for all of their power needs. The three large members are “partial requirements members,” or PRMs, w ho have contracted with AEPCO for only some of their power needs. The PRMs are free to supplement their AEPCO power supply and/or, subject only to contractual minimum provisions, buy market power to substitute for scheduling energy from their AEPCO power supply.

Because AEPCO’s members are independent, they retain the ability to determine whether AEPCO’s costs have gone out of line and, if so, to exert pressure through their representatives on AEPCO’s board or, in compelling situations, to contract for pow er elsewhere despite existing contractual requirements. This differs from many situations where the rate payers may have the theoretical right to contract elsewh ere, but do not have the effective ability to do so. In this case, AEPCO’s ultimate rate payers are already organi zed into cooperatives that can contract at

wholesale to take their busi ness elsewhere should AEPCO’s costs become non-competitive. This dynamic is critical to understanding th e impact on AEPCO of requiring SCR on Apache

Station Units ST2 and ST3.

2. Air Pollution Control Equipment Capital and Operating Costs Are Passed on as Fixed and O&M Charges to AEPCO’s Class A Members Not Through the Energy Cost

Rate Schedule A of the Class A Members’ Wholesale Power Contracts or Partial Requirements Capacity and Energy Agreements specifies the rates and charges and the methodology for developing and administering thos e rates and charges for capacity and energy

1 EPA, “Arizona Regional Haze SIP, BART Determination for Apache Generating Station, Supplemental Economic Analysis,” at 5 (Nov. 7, 2012).Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 5

sales made by AEPCO to each of the Class A Memb ers pursuant to their respective contract or

agreement. See Att. B
, Rate Schedule A, page A-1.

Monthly charges to the Class A Members are ca lculated and billed in accordance with the Wholesale Power Contract or Partial Requireme nts Capacity and Energy Agreement and consist primarily of a Monthly Fixed Charge, Monthly O&M Charge, Base Energy Charge, Base Fuel Cost Adjustor Charge, Other Energy Charge, and Other Fuel Cost Ad justor Charge. Att. B, Rate Schedule A, page A-3. AEPCO’s expenses and non-tariff revenues are cl assified by functional categories of Fixed Expenses, O&M Expenses a nd Energy Expenses. Att. B, Exhibit A-2 to Rate Schedule A, pages A-2.1 through A-3.3.

The addition of SCR (or other air polluti on control equipment) to ST2 and ST3 would result in increased depreciation, taxes, interest an d insurance costs. These costs are classified to the functional category of Fixed Expenses and re sult in increased Monthly Fixed Charges to the Class A Members. In addition, increased operati ons and maintenance costs would be classified as O&M Expenses resulting in increased Mont hly O&M Charges to the Class A Members. Therefore, the costs of the SCR (or other air po llution control equipment) would not run through the energy rates, but rather through Fixed and O&M Charges. This cost allocation to fixed, not per-kWh charges, is a critical fact that is misunderstood in the EPA (and its contractor’s) analysis. Att. C, Affidavit of Gary E. Piers on, AEPCO Director of Financial Services, ¶ 4, first bullet (hereafter “Pierson Aff.”).

B. There Are Significant Errors in EPA’ s Cost and Affordability Analysis

In its FIP, EPA states that AEPCO could “s pread[] the incremental SCR cost across all kWh produced at Apache, both Member Co-ops a nd off-system or non-Member sales.” 77 Fed. Reg. at 72540-41. EPA apparently obtained this in correct concept from its contractor, EC/R. 77 Fed. Reg. at 72540-41. In turn, EC/R apparen tly obtained this information from its subcontractor, Energy Strategies, LLC. Energy Strategies, LLC, “Apache Plant: Report on SCR Incremental Cost Assessment,” (Nov. 9, 2012, EPA Contract EP-D-10-096, WA 3-04) (hereinafter ES Report). This assumption by EPA and its cont ractor and subcontractor is incorrect at multiple levels. Similarly, EPA a ppears to believe that AEPCO or its member cooperatives have existing financia l resources that would ameliorate the cost of installing SCR. That assumption is also incorrect.

1. AEPCO Does Not Have the Physical Capacity to Produce Significant Excess Energy for Off-System Sales

AEPCO does not have uncommitted reliable physical capacity in the ST2 and ST3 units to produce the quantity of market able excess energy postulated in th e ES Report. In its report, Energy Strategies states that AEPCO has th e potential to genera te 3,037,968 MWh of energy, while selling 2,513,087 MWh to its members. ES Repor t at 5-6. Energy Strategies then assumes that “AEPCO may be able to dispose of 524,881 MWh in 2019 by selling that production in to the bulk power market.” ES Report at 6.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 6

Energy Strategies apparently derive s its postulated 3,037,968 MWh of energy by multiplying AEPCO’s “capacity factor” of 0.85 by the full nameplate capacity of ST2 and ST3 of 204 MW each. If correct, this would give the nominal “potential” generation of 3,037,968

MWh. It is not correct.

AEPCO’s correct net generating capacity is only 175 MW per unit due to auxiliary loads at Apache and power reserve requirements. See Att. D, AEPCO Energy Information Administration (EIA) Form 890 Report, at 2-3. In other words, Energy St rategies overstates the ST2 and ST3 capacity by 16.7%. As discussed la ter, the SCR would redu ce the coal generating capacity by another 1.2 MW. Using the correc t net generating capacity, AEPCO only has a “best-case” realistic poten tial of 2,606,100 MWh at 0.85 capac ity factor—more than 430,000 MWh less than the sales potential Energy Strategi es asserted in its report. AEPCO’s actual generation figures from ST2 and ST3 since 2004 are included in Att achment E, AEPCO’s Generator Summary Reports from 2004 to 2011. See also Att. F, Declaration of Richard E. Stinneford, Managing Member, Washington Utilit ies Group, LLC, ¶ 5.c. (h ereafter “Stinneford Decl.”).

2. AEPCO Does Not Have the Contractual Authority to Sell Significant Excess Energy on Its Own Account.

In addition to assuming that AEPCO has spare energy available from ST2 and ST3, which it does not have, Energy Strategies also cr iticized AEPCO’s cost analysis because “the analysis should account for a share of the SCR co st going to the off-system sale volumes and not only allocated to member rates.” ES Report at 6. This assertion is incorrect and reflects two fundamental misunderstandings of how AEPCO serves its members.

First, as discussed in Section I.A.2 above , the AEPCO Class A Member wholesale power contracts specify that fixed charges (i.e., such as the increased depreciation, taxes, interest, insurance, etc. associated with SCR) are recovere d in the monthly fixed charge rates of the Class

A Members and not through the energy rate. See Att. B, Rate Schedule A and Exhibits A-2, A-3 and A-4 of Rate Schedule A. Therefore, all SCR financing costs must be directly charged to the

Class A Members and their rural customers re gardless of whether AEPCO can or does make sales of surplus energy. Att. C, Pierson Aff. ¶ 4, second bullet.

Second, AEPCO’s three Partial Requiremen t Members (PRMs) control XXX% of ST2 and ST3 capacity. Att. B, Rate Schedule A, Appendix A to Exhibit A-5. The PRMs schedule that capacity, not AEPCO. As a result, even though the PRMs are not specifically dedicated control and operation of their al located capacity portion of ST2 and ST3, AEPCO’s obligation to meet their hourly schedules and potential sc hedule changes precludes AEPCO from committing

to sell from the PRMs interest in AEPCO units mo re than on a spot market basis. Att. G, Affidavit of Richard P. Kurtz, AEPCO Vice Pr esident of Power Resources and Planning, ¶ 4, first bullet (hereafter “Kurtz Aff.”). Additionally , if the PRMs’ energy costs from their interest in AEPCO units are less than the energy cost th at can be obtained on the economy market, thenPetition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 7

the PRMs will make the off-system sales, not AE PCO, and the benefits would flow to them through the Purchase Power and Fuel Adjustment Clause (“PPFAC”) and, eventually, the energy rates. Att. B, Exhibit A-4 to Rate Schedule A, page A4-17. If the PRMs are not “in the money,” AEPCO would not be in the money either and sa les will not be made because they would be made at a loss to AEPCO and its members. Att. H, Affidavit of Walter T. Bray, AEPCO Director of Energy Services, ¶ 4, firs t bullet (hereafter “Bray Aff.”).

AEPCO does control the scheduling for its All Requirements Members (ARMS), which accounts for the remaining XX% of AEPCO’s capaci ty. However, as with the PRMs, although AEPCO does the scheduling, any sales are for th e benefit of AEPCO’s members and revenues are shared among the ARMs on a contract basis. As with the PRMs, if the ARMs cannot make money on a sale, AEPCO cannot make money either. Att. G, Kurtz Aff. ¶ 4, second bullet.

In short, all of AEPCO’s gene ration capacity is dedicated to the Class A Members. It is not, as Energy Strategies wrongly as serts, available for AEPCO to c ontract for or profit from as an off-system sale. See Att. B, Appendix B to Exhibit A-5 to Rate Schedule A; Att. G, Kurtz Aff. ¶ 4, third bullet.

Because (1) AEPCO does not have the energy ca pacity that the ES Report assumes; (2)

AEPCO’s members benefit from a ny margins on off-system sales; and (3) in any event, all SCR costs would be recovered through fixed monthl y charges to AEPCO’s Class A Members, not energy sales proceeds, the ES Report grossly unde restimates the costs and overestimates the potential for recovery of the costs imposed by the FIP SCR requirement on AEPCO and its

members.

3. Apache Station’s Age and Heat Ra te Weighs Against Surplus Energy

Sales

AEPCO’s Apache Station ST2 and ST3 units ar e over 30 years old. As a result of their age, ST2 and ST3 have a relatively high “heat rate.” A high heat rate means that their relative energy cost is high compared to the market. The current net heat rates of AEPCO’s ST2 and

ST3 are:

Table 1. AEPCO Net Heat Rates, Btu/kWh Unit Full Load Net Heat Rate Avg. Net Heat Rate (3 yr, 62%)

ST2 XXXX XXXX

ST3 XXXX XXXX

Combined ST2/ST3 XXXX XXXX

The approximate average heat rate of a newe r combined cycle unit would, for comparison purposes, be in the range of 7,000 to 7,800 Btu/kW h at the approximate elevation of Phoenix, Arizona. Att. I, Affidavit of Barry A. Brown, AEPCO Director of Engineering, ¶ 4, first bullet (hereafter “Brown Aff.”).Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 8

Because of the relatively high heat rate of AEPCO units ST2 and ST3, the economy market price needs to become relatively high be fore AEPCO or its members can make margins over ST2 or ST3 energy costs for sale into th e market. And, as discussed under #2 above, the revenues from such sales go to AEPCO’s members, not to AEPCO. Att. H, Bray Aff. ¶ 4,

second bullet.

4. EPA’s BART Determination May H ave Been Influenced by an Erroneous Understanding of AEPCO’s Earnings Position and Internal Financing Capacity

EPA cites the Chernick Report in the preambl e to the FIP for the proposition that AEPCO has capital resources, operating margin and a coal contract recovery to fi nance the bulk of the cost of the SCR system. 77 Fed. Reg. at 72539. To its credit, EPA noted that “[w]hile some of these funds may be available for capital expe nditures such as pollution controls, we have assumed for the purpose of our analysis that fina ncing will be necessary to achieve the pollution reductions required by our action.” 77 Fed. Reg. at 72540. AEPCO agrees with EPA’s conclusion and wishes to emphasize why financing will be required.

First, as noted elsewhere, AEPCO does not ha ve “capital” in the trad itional sense of an investor owned utility. Instead, AEPCO has “patronage capital,” wh ich is retained earnings not yet returned to its members. Only the patronage capital necessary to maintain financial stability is retained at the generation coope rative. Any excess is required to be returned to the members. Att. J, Affidavit of Peter F. Scott, AEPCO Ch ief Financial Officer, ¶ 4, first bullet (hereafter “Scott Aff.”); Att. A, AEPCO Bylaws, § 7.02.

AEPCO does not have any ability to issue equ ity instruments and generally does not have the ability to seek capital cont ributions from its members for capital expenditures. All expenditures for plant improvements or retrofits such as SCR are financed by debt instruments secured by the RUS mortgage. In short, AEPCO does not have the ability internally to raise capital. Att. J, Scott Aff. ¶ 4, second bullet.

Second, AEPCO’s operating margins generally ar e fairly thin and net cash flows have been historically flat and freque ntly negative. This net cash eff ect can be seen even during the years of relatively strong net ma rgins referenced in the Chernick report. Routinely, principal payments and non-operating expenditures result in little remaining cash margin. The margins generated by AEPCO’s present (or pending) rates ar e not adequate to cover either the fixed costs or the O&M costs that would likely be incurred by implementation of SCR systems. As noted in AEPCO’s comments, operating margins have been less than or little more than the amount

needed to finance the increase in debt servi ce. Because capital construction costs are front loaded, AEPCO does not have the internal abil ity to finance the construction of the SCR systems. It must have a loan, which must be secured by the RUS mo rtgage and AEPCO must meet RUS’s TIER and DSC covenant requireme nts. These mortgage covenants cannot be achieved with the margins provided by AEPCO’s present (or pending) ra te structure if SCRPetition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 9

systems are implemented. Significant rate increa ses would be required. A tt. J, Scott Aff. ¶ 4,

third bullet.

Third, it is true that on November 22, 2011, AEPCO received a favorable ruling from the Surface Transportation Board (“STB”), which awar ded AEPCO prescribed rail rates for a ten year period from the date of the filing, December 30, 2008. $9.2 million of reparations were paid retrospectively to reimbur se AEPCO for amounts of unreasona bly high rail rates charged by the railroads during the pendency of the ST B case (2009-2011). The STB estimated that

AEPCO’s future rail rates would be reduced by $53.8 million over the remaining seven year life of the rate prescription, the period of 2012- 2018. The STB projected the savings based on AEPCO’s based on 2009 shipments, but AEPCO’s shipments starting in 2011 have been at a substantially lower level. In a ddition, the effect of the estimated $53.8 million of future relief is already included in the anticipated rates used in AEPCO’s financial forecast and cannot be

counted twice to reduce members’ rates. AEPCO has a PPFAC through which under- or overcollection through rates of fuel cost s are passed on to purchasers of its power, either as a charge or refund respectively. Through this process, no f unds are generated that can be used to offset the cost of pollution control equipment. As rail rates are a part of the fuel expense that flows through the PPFAC, the reduced rail rates orde red by the STB will be refunded through the

PPFAC mechanism and will not increas e cash at AEPCO. Att. C, Pierson Aff. ¶4, third bullet.

Of the reparations amount of $9.2 million, approximately $XX million will be refunded according to contract provisions to parties th at AEPCO had long term power sales agreements with during that time period (since expired). Th e remaining $XX million of reparations will be refunded back to its members through the PPFAC mechanism. The reparations have not been flowed through the PPFAC pending the outcome of a ppeals of the STB decision and order. Att. C, Pierson Aff. ¶ 4, fourth bullet.

C. Installation of LNB + OFA + SCR, Added to Other BART Costs, Is

Unaffordable Because It Renders ST2 and ST3 Non-Viable

Congress, in establishing th e BART requirement, included co nsideration of cost and the remaining economic life of the unit. 42 U.S.C. § 7491(b). Congress also provided that greater flexibility should be provided for the review of “small” elect ric generating powerplant of less than 750 MW. 42 U.S.C. § 7491(b)(2). Clearly, AEPCO is such a “small” generating plant entitled to greater latitude in the BART determination.

EPA has recognized that “[e]ven if the [p roposed BART] control technology is cost effective, there may be cases where the installation of controls would affect the viability of plant operations.” 40 C.F.R. Part 51, App. Y, § IV.E .3(1). EPA specifically noted that “effects on product prices, the market share, and profitabili ty of the source” should be considered in determining whether a proposed BART is appropriate. Id. § IV.E.3(2). Apache Station’s ongoing viability is clearly at st ake should SCR plus scrubber upgrades be imposed on ST2 and

ST3.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 10

1. The Costs of Installation of LN B + OFA + SCR Are Approximately $192 Million

As described in AEPCO’s initial comments, its response to EPA’s information request, and its final comments, the total cost of SCR installation is estimated at approximately $192 million. AEPCO recognizes that EPA disagrees as to whether all of these costs are appropriately considered in determining the cost of control. AEPCO is not, however, c ontending that its costs of control on a $/ton of pollutant basis are subs tantially out-of-line with those for some other utilities. Instead, AEPCO’s contention is that the overall cost of the BART determination for Apache Station is unaffordable and will affect the viability of Apache Station operation. Because plant viability is a different question than cost effectiveness, 2 AEPCO believes that a correct analysis requires consider ation of costs which might be excluded in the cost effectiveness analysis.

In Attachment K, AEPCO has itemized the additional costs that EPA excluded from AEPCO’s cost analysis in the preamble to the fi nal Rule. AEPCO has documented why each of those costs are expenses that will actually be incurred and thus burden AEPCO’s future operations. Att. C, Pierson Aff. ¶ 4, fifth bullet. Accordingly, EPA shoul d give consideration to the full $192 million cost of LNB + OFA + SCR installation for purposes of evaluating the impact on plant viability.

If EPA disagrees, perhaps taking the position that some or all of these costs will not be actually incurred by AEPCO, EPA must provide a reasoned basis for that position, explaining why these costs would not be incurred or would not be included in AEPCO’s financing cost and the corresponding cost charged to its members and their ratepayers. The mere fact that these costs may not be known with certainty is not a basis for categorically excluding them; they are

still real costs that must be accounted for in construction and wh ich will be borne by AEPCO, its

members and their retail members. Att. C, Pierson Aff. ¶ 4, sixth bullet.

2. The Cost of Installation of SO 2 Scrubber Upgrades Mandated by BART Is an Additional $14 million, Bringing the Total Cost of BART for Units ST2 and ST3 to $206 Million

In addition to the LNB + OFA + SCR cost, AE PCO is also required to install certain scrubber upgrades by the SIP-approved BART. See ADEQ, Section 308 SIP, App. D, Table 1.3; 40 C.F.R. § 52.145(e)(1). The cost of these units is estimated at $14 million. Attachment L sets forth an engineering overview of the costs of installation. The total cost of BART for ST2 and ST3 is thus expected to be approximately $206 million.

The full BART cost of $206 million is the appr opriate benchmark against which to assess affordability. Some additional controls on ST1 are also required, but these affect the cost of that

2 Compare Guidelines § IV.D.4(4) & (5) (referring to EPA’s Control Cost Manual as determining which costs are to be considered) with § IV.E.3 (broad consideration of “where the inst allation of controls would affect the viability of continued plant operations” and recommending an “economic analysis”).Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 11

unit, not ST2 or ST3, and hence do not have th e same direct economic impacts as the SCR

installation on units ST2 and ST3. AEPCO is thus concentrating its anal ysis on the impact of

these costs on the future use a nd viability of Units ST2 and ST3.

3. The Annualized Fixed Financing Cost to AEPCO of the LNB + OFA +

SCR and SO 2 Scrubber Upgrades Is Appr oximately $21.5 Million per

Year

Applying annualized assumptions, as set fort h in Attachment M, the additional fixed charges of adding the SCR system and the upgraded scrubbers to ST2 and ST3 is approximately $21.5 million per year. These costs will be added to AEPCO’s existing fixed charges for these units. The following table summarizes the impact on AEPCO’s fixed charges:

Table 2. Fixed Cost Impacts of SCR + Scrubber Upgrades Category AEPCO Comments (projected 2020) Annualized Existing Fixed Charges $ XXXXXX

Annualized Fixed Charges

Increase for ST2 & ST3 SCR + scrubber upgrades $ 21,537,000

Total Annualized Fixed Charges: $ XXXXXX XXX% increase in annual fixed charges

Net KW-Months XXXXX Forecast demand in 2020 Fixed Charges, $/KW-Month $ XXX $/KW-Month, XX% increase

In the last two lines of Table 2, AEPCO has conve rted the increase in annua l fixed charges to its corresponding cost in $/KW-Month, which is the un it of measurement typically used to purchase or sell long term or “firm” electrical capaci ty. Based on AEPCO’s projected power sales from existing system resources to its members, AEPCO will have a total fixed charge cost expressed on a $/KW-Month of approximately $XXX. Conv erting fixed charges to $/KW-Month allows a better understanding of the impact of the increase in fixed costs on AEPCO’ s cost structure and competitive position.

4. The O&M Cost to AEPCO of the LNB + OFA + SCR and SO 2 Scrubber System is $10.7 Million Per Year.

In addition to the financing costs, installa tion of the SCR and scrubber upgrades will impose additional Operations and Maintenance (O&M) costs on AEPCO. These costs were estimated at $ 10.7 million annually (in 2020 dolla rs) for the SCR and scrubber upgrades. The details for these cost analyses are set fort h in Attachment K (LNB + OFA + SCR) and Attachment L (scrubber upgrades). As noted ab ove, O&M represents part of the Monthly O&M Charge that AEPCO charges its members. The following table summarizes the impact on AEPCO’s O&M expense.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 12

Table 3. O&M Impacts of SCR + Scrubber Upgrades Category AEPCO Comments (projected 2020) Annualized Existing O&M $ XXXXXX

Annualized O&M Increase for SCR and scrubber upgrades $ 10,763,000

Annualized Total O&M $ XXXXXX XX% increaseTotal O&M Charges, $/KWMonth $ XXX

In the last two lines of Table 3, AEPCO has c onverted the increase in monthly O&M charges to its corresponding cost in $/KW-Month, which is the unit of measurement typically used to purchase and sell long term capacity. Based on AEPCO’s projected power sales from existing resources to its members, AEPCO will have a total O&M charge cost per KW-Month of approximately $XXX. Converting O&M charges to $/KW-Month allows a better understanding of the impact of the increase in O&M costs on AEPCO’s cost structure and competitive position.

5. The Combined Effect of Fixed Costs and O&M Costs on AEPCO’s Effective $/KW-Month Capa city Cost Is Material

Adding the SCR and scrubber upgrade-related fixed charges and O&M charges to the existing fixed and O&M charges gives AEPCO’s “new” capacity cost in $/KW-Month. That

cost is estimated as follows:

Table 4. Capacity Cost with SCR + Scrubber Upgrades Category AEPCO (projected 2020) Existing Fixed Charges $/KW-Month $ XXX

Existing O&M $ XXXX Total Existing Fixed and O&M Charges, $/KW-Month (Capacity Charge) $ XXXX

Additional Fixed Charges for SCR + Scrubber Upgrades $/KW-Month $ 5.00

Additional Fixed O&M Costs for SCR + Scrubber Upgrades $/KW-Month $ 2.50

Total Additional Fixed & O&M

Costs for SCR + Scrubber Upgrades, $/KW-Month $ 7.50Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 13

Category AEPCO (projected 2020) Post-BART Capacity Charge $/KW-Month $ XXX

AEPCO’s capacity charges, expressed in a $/KW-Month basis, will increase by XXX% to recover the SCR and scrubber upgrade relate d cost for ST2/ST3 base d on projected member

demand of XXXXX KW-Months in 2020. Class A Me mbers’ loads and consequent sales of energy from AEPCO resources are not forecast to gr ow significantly in the next ten years. Using

the fixed and O&M costs discussed above translat es to additional charges to AEPCO’s Class A

members as follows:

Table 5. Impact of Costs on AEPCO Class A Members AEPCO Member Group Percent Capacity Cost Impact Collective All Requirements Members (Anza, Duncan, Graham Electric Cooperatives) XX XXXXXXX

Mohave Electric Cooperative XX XXXXXXX Sulphur Springs Valley Electric Cooperative XX XXXXXXX Trico Electric Cooperative XX XXXXXXX

Att. C, Pierson Aff. ¶ 4, seventh bullet.

AEPCO’s members must pay these fixed char ges whether they pur chase any electricity

from AEPCO or not . It is also important to rea lize that AEPCO’s members must act on this information quickly given the time lag associat ed with AEPCO’s options including, but limited to purchasing power, installing ai r pollution controls, or buildi ng new assets should alternate courses of action be deemed necessary or prudent by AEPCO or its members. Att. J, Scott Aff. ¶ 4, fourth bullet.

6. Apache Station Units ST2 and ST3 Operate in a Competitive Market

As a result of area-wide cha nges in wholesale and retail elec tric supply, there is now a very competitive marketplace for the sale of capacity and energy. Not only AEPCO can participate in these markets, but also AEPCO’s Class A members could as well. The existence of competitive markets means that ST2 and ST3 mu st be situated to compete in those markets with reliable, reasonably-priced energy to retain AEPCO’s members. Att. H, Bray Aff. ¶ 4, third

bullet.

Determining the “market rate” for capac ity is a constantly changing and dynamic exercise. While AEPCO obviously knows its own $/KW-Month capacity rate, it does not know what that rate is or will be for its competitor s. Instead, AEPCO and its members must proceed by analysis and informed judgment.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 14

In this case, AEPCO can draw some conc lusions from two recent developments: the Southwest Public Power Resources (“SPPR”) Gr oup Purchase Power Agreement (“PPA”) with Sempra Generation, and Salt River Project’s (“ SRP’s”) recent purchase of one block of the Mesquite Generating Station from Sempra Generation.

 The SPPR PPA, involves 21 public entities:

o The PPA is based on a capacity fixed cost of $XXX KW-Month plus a fixed O&M charge, presently estimated at $ XXX KW-Month, for a total fixed cost of approximately $XXX KW-Month in 2015. The $XXX is fixed, but the $XXX escalated at 3% annually w ould be $XXX in 2020 and the total fixed would then be $XXXX. Att. G, Kurtz Aff. ¶ 4, fourth bullet.

o The PPA energy cost is based on natural gas at the So-Cal Border daily index as a fuel cost, applied to a he at rate of XX MMBtu/MWh, increased by a sales tax of 5%, plus a variable O&M charge starting at about $XXX per MWh in 2015. Escalating the $XXX by 2.5% annually would be $XXX in 2020. Att. G, Kurtz Aff. ¶ 4, fifth bullet.

 SRP recently purchased one block of the Mesquite merchant power plant for $371 million. Mesquite is a dual 624 MW na tural gas combined-cycle plant.

o Using standard assumptions for financi ng costs, the capacity costs would be $7.50-8.50/KW-Month, lower than the SPPR PPA. AEPCO assumes that the

fixed and variable O&M costs are the same as stated in the SPPR PPA, as those are based on the same Sempra Generation pl ant. Att. C, Pierson Aff. ¶ 4, eighth

bullet.

o Finally, we assume that the energy cost w ould be essentially the same formulation as in the SPPR PPA, but based on th e actual heat rate (estimated 7000 mmBtu/kWh) and the actual cost to SRP of the natural gas. Att. G, Kurtz Aff. ¶ 4, sixth bullet.

By comparison, AEPCO ST2 and ST3 operate wi th a best case heat rate in the XXXXXXX MBtu/kWh range at the present time and, due to ag e, significant improvement in those heat rates would not be anticipated. AEPCO has calculate d its average actual net heat rate for ST2 and ST3 over the last three years at XXX MBtu/kWh based on an average capac ity factor of XX%. Att. I, Brown Aff. ¶ 4, second bullet.

Valley Electric Associati on obtained a forward power estimate from ACES Power marketing to assist in the long-term valuation of the Sempra PPA discussed above. Critically, the ACES analysis discussed two issues: Forwar d Power Demand, priced in $/MWh, and Market Implied Heat Rate (MBtu/kWh). This forecas t shows on-peak power demand increases from $XXXX/MWh in the 2017-2018 period to perhaps as high as $XXXX/MWh in 2028. However, it also shows that the market implied heat rate will decline from a present XXX MBtu/MWh in 2018 to approximately XXX MBtu/MWh to approximate ly 2020. Att. G, Kurtz Aff. ¶ 4, seventh

bullet.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 15

AEPCO also obtained another forward power es timate from ACES that projects the likely range of the market implied heat rate from 2013 to 2018, which AEPCO has extrapolated to 2020. Essentially, this is the heat rate that ST 2 and ST3 must meet to be in the money going forward. Based on the mean market implied heat rate, AEPCO ST2 and ST3 would be in the money only two months of each year from 2013 to 2017 and three months from 2018 through 2020 on an energy basis only.

7. Apache ST2 and ST3 Are Non-Viab le with SCR + Scrubber Upgrade

Costs Added

AEPCO believes that ST2 and ST3 are non-vi able with the added costs of SCR and scrubber upgrades. First, and less importantly, SCR imposes an additional energy cost because it reduces the capacity output of ST2 and ST3 by 1.2 MW for the same coal input. With this adjustment, AEPCO’s full load heat rates are as follows:

Table 6. AEPCO’s Post-SCR and Scrubber Upgrade Heat Rate Units Firing Adjusted Full Load Net Heat Rate

AEPCO on ST2 and ST3 on coal XXXX Btu/kWh

AEPCO on coal w/SCR XXXX Btu/kWh AEPCO on gas XXXX Btu/kWh

Att. I, Brown Aff. ¶ 4, third bullet. In additi on, the heat rate, and the associated energy cost ($/MWh), will be higher if ST2 and ST3 operate at less than full output. In contrast, a modern combined cycle gas turbine may have heat rate s in the 7,000 to 7,800 Btu/kWh range in much of Arizona. Att. H, Bray Aff. ¶ 4, fourth bullet. Any deterioration in the heat rate, and the corresponding increase in energy cost, will cause overall cost to increase on a $/MWh basis.

The result of this cost differential is that there will be few times, except at peak energy demand, when ST2 and ST3 will be cost effectiv e on an energy cost basis. Thus, AEPCO’s members will not “buy” energy from ST2 or ST3, but rather will purchase “against” ST2 or ST3 and buy their power from outside sources. As a re sult, utilization of ST2 and ST3 will fall to the

minimum contract levels of XXX MW combined. Att. H, Bray Aff. ¶ 4, fifth bullet. However,

the Wholesale Power Contract between AEPCO and its Members provide for waiver of the contract minimum if the Member’s actual hour’ s load is lower than its Allocated Capacity Percentage (ACP) of available capacity of ST2 a nd ST3. It is thus not certain that even the

contract minimum of XXX MW combin ed will be maintained at all times. Att. G, Kurtz Aff. ¶ 4, eighth bullet. Below contract minimum, ongoing operation of a unit becomes less reliable due to operational constraints. Att. I, Brown Aff. ¶ 4, fourth bullet.

Second, and more importantly, when fixed costs are added, the implications of the market

trends discussed in section I.C.6 above for AEPC O if SCR is required to be added to ST2 and ST3 are grave, as can be seen in the following analysis:

Table 7. Annualized Market Impact on AEPCO of SCR + Scrubber UpgradesPetition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 16

Market Price Forecast (ACES) Peak Rate Wrap Rate Comments High Price, $/MWh Based on market Low Price, $/MWh AEPCO/PPA Cost Comparison PPA AEPCO Comments Fixed Charge, $/KW-Month O&M Charge, $/KW-Month Capacity Charge, $/KW-Month Capacity = Fixed + O&M Capacity Charge, $/MWh Based on forecast energy

usage Variable O&M Charge, $/MWh PPA is SPPR escalated at

XXX% Energy Charge, $/MWh Assumes gas at $XX and coal at $XX ($/MMBtu). 3 Total Cost, $/MWh

The Table 7 analysis shows:

 That AEPCO will operate with a premium over market of approximately $XXXX/MWh versus a long term PPA’s equivalent total cost XXXXXX XXXXXXXXXXXXX.

 That AEPCO will operate with a cost structure in excess of its likely recovery in either Peak or Wrap rates in 2020. On a peak ba sis, AEPCO’s deficit ranges from -XXXX to - $XXXXX/MWh. On a wrap basis, AEPC O’s deficit ranges from -XXXX to - $XXXXX/MWh.

 Energy charges are more variable and difficult to forecast, but if natural gas remains cheap, then AEPCO’s energy cost advantage (coal over natural gas) will decline, rendering AEPCO’s energy charges less compet itive. As forecast, AEPCO is very concerned that its energy charges may only be competitive in 2 to 3 months a year.

 As forecast, AEPCO is wholly non-competitive on a long-term capacity basis. Its ability to compete on the spot market is also impaired. Att. H, Bray Aff. ¶ 4, sixth bullet (Table 7 is erro neously called out as Tabl e 6 in this Affidavit).

This premium over the market and competitive PPA s is unsustainable. Att. G, Kurtz Aff. ¶ 4, ninth bullet. As it applies to AEPCO’s PRMs, the difference in cost of staying in AEPCO versus leaving AEPCO and buying power on the open market becomes quite large. Here is the

breakdown:

3 If gas is cheaper, that adverse effect on AEPCO becomes greater.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 17

Table 8. AEPCO Premium Over Market AEPCO Member Group Annual Premium Collective All Requirements Members (Anza, Duncan, Graham Electric Cooperatives) Mohave Electric Cooperative Sulphur Springs Valley Electric Cooperative Trico Electric Cooperative

While it is true that there are contractual im pediments to a PRM (or ARM) leaving AEPCO, member cooperative boards have legal duties to thei r members. As stated in the affidavits of the

chief executive officers of Mohave Electric Co operative, Sulphur Springs Valley Electric Cooperative and Trico Electric C ooperative (AEPCO’s PRMs), th e capacity premium and energy charges resulting from SCR + scrubber upgrades, if incurred as presently promulgated, will result in each PRM minimizing purchases of AE PCO power and reviewing all available options to reduce exposure to AEPCO costs—includi ng potentially withdraw ing from AEPCO. See Att. P, Affidavit of J. Tyler Carlson, Chief Executive Officer, Mohave Electric Cooperative, Inc., ¶¶ 6, 8; Att. Q, Affidavit of Creden W. Huber, Chief Executive Officer, Sulphur Springs Valley Electric Cooperative, Inc., ¶¶ 6, 8; Att. R, Affidavit of Vincent Nitido, Chief Executive Officer/General Manager, Trico Electric Coopera tive, ¶¶ 6-8 . If even one PRM leaves and shifts their costs to the remaining members, the premium upon the remaining members would increase by 45% to 79%. What would likely happ en is that AEPCO woul d dissolve, leaving all of the Apache Station Units potentially as stra nded assets. Given the heat rate and other penalties discussed above, it is not clear th at a purchaser could be found for the assets, particularly if encumbered by the LNB + OFA + SCR and scrubber upgrade requirements. Att. G, Kurtz Aff. ¶ 4, tenth bullet; see also Att. F, Stinneford Decl. ¶ 5.f.

AEPCO retained Richard E. Stinneford, Managing Member of th e Washington Utility Group, LLC (“WUG”), to provide a third party review of AEPC O’s financial projections and discussion above in this petiti on for administrative reconsiderat ion. AEPCO commissioned this review by WUG to provide assuran ce to EPA that the projections included in this petition are based upon real circumstances and concerns. Based upon his over 30 years of experience, Mr.

Stinneford concluded:

 The financial assumptions and rate forecasts generated by AEPCO are appropriate. Att. F, Stinneford Decl. ¶ 5.a.

 AEPCO’s assumptions with respect to the potential output of the [Apache Generating Station] are correct and those of Energy Strategies are incorrect. Att. F, Stinneford Decl. ¶ 5.c.

 AEPCO’s and its members’ ability to off-load any incremental costs associated with the SCR + scrubber system is “extremely limite d.” Att. F, Stinneford Decl. ¶ 5d.

 Costs increases resulting from the EPA’s ruling will drive AEPCO’s wholesale rates further above regional market rates. Att. F, Stinneford Decl. ¶ 5.e.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 18

 Should increases in wholesale rates lead to the default or withdrawal of an AEPCO member, it draws into question the continued vi ability of AEPCO. Att. F, Stinneford Decl. ¶ 5.f.

Mr. Stinneford’s declarations provide assura nce that AEPCO’s concerns are well-founded and not speculative. AEPCO’s members are very concer ned, as expressed in the affidavits of their

chief executive officers discussed above and included in Attachments P, Q and R to this petition.

II. EPA Should Reconsider Including GT1 in the ST1 BART Determination

Upon reviewing the BART determination forma lized by EPA’s SIP approval in part and disapproval in part and FIP, AEPCO developed a question about how to account for emissions from Gas Turbine #1 (GT1) when they are ducted through ST1. GT1 is a simple cycle combustion turbine located adjacent to ST1 that can have its exhaust either routed through its

own stack or introduced into the windbox of ST 1, where it adds heat to the ST1 boiler windbox, in which case the exhaust exits through the ST1 stack.

In its BART submittal to ADEQ, AEPCO listed units ST1, ST2 and ST3 as potentially BART-eligible. See “BART Analysis for Apache Generating Station, Steam Unit 1,” CH2MHill (Dec. 2007) [Hereinafter CH2MHill Report]. The CH2MHill described ST1 as follows:

ST1 is a wall-fired steam electric genera ting unit that can burn pipeline natural gas (PNG) and No. 2 through No. 6 fuel oils. The unit typically produces up to 71 MW, but is permitted to produce up to a maximum capacity of 85 MW. Currently,

there is no emissions contro l equipment installed on ST1.

ST1 is located adjacent to Gas Turbin e #1 (GT1) at Apache Generating Station. These two units can be operated separately or in a combined cycle configuration. Typical practice is to operate these units together, and under this case GT1 exhaust is routed through the ST1 boiler. Although GT1 emissions can contribute

to total emissions from the ST1 stack wh en the units are operated in a combined cycle configuration, only ST1 is BART elig ible. Therefore, ST1 is considered a

stand-alone unit for th is BART analysis.

CH2MHill Report at 2-1. In the BART techni cal demonstration, CH2MHill recommended that Low NOx Burners (LNB) plus Flue Gas Recirculation (FGR) be us ed. It was recommended that the FGR be obtained from the existing GT1 exhaust. CH2MHill Report at 3-7 & 5-36.

CH2MHill also noted that FGR coul d come from other sources, as well as GT1. It is apparent that AEPCO and its contractor, CH2MHill, di d not propose to extend BART to GT1 beyond the narrow context of when it is providing FGR to support the ST1 BART recommendation.

ADEQ, in its BART SIP, determined that “for Unit 1, BART for NOx is the installation of LNB with FGR (from GT1) with a NOx emissions limit of 0.056 lb/MMBtu when burning pipeline quality natural gas (PNG).” ADEQ, T echnical Support Document for Arizona BARTPetition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 19

Analyses and Determinations, page 54 of 115 [hereinafter ADEQ TSD] . Significantly, ADEQ stated that “Apache Steam Unit 1 is a wall-fi red steam electric genera ting unit that can burn natural gas and numbers 2 through 6 fuel oils .... The remaining four units at the Apache Generating Station are simple cycle gas turb ines. Steam Unit 1 and Gas Turbine 1 can be operated separately or in a combined cycle conf iguration.” ADEQ TSD, at 49 of 115. From this description, it is apparent that ADEQ also treated the relevant un it as ST1, including GT1 only to the extent that it is providing FGR to ST1 in “combined cycle” operation.

In the intervening period, AEPCO discusse d the status of ST1 and GT1 combined operations, which AEPCO had listed as “combin ed cycle,” with EPA Clean Air Marketing Division (“CAMD”). Based upon CAMD’s review , AEPCO was advised to reclassify the ST1/GT1 combined operation from “combined cycl e” to “wall-fired boile r.” A copy of that correspondence is included in Attachment N.

In a document entitled “Questions for AZ Regional Haze FIP Conference Call” prepared by EPA Region IX and dated January 22, 2013 [her einafter EPA Region IX Q&A], EPA took the position that:

Under the BART Guidelines, combined cycle turbines that are part of a fossil-fuel fired steam electric plant more than 250 million Btu/hour heat input are BARTeligible. Thus, based on the information in the SIP, it seems that GT1 is, in fact, part of the BART-eligible unit, so its em issions should be included in determining compliance. However, additional information from AEPCO and ADEQ may be

needed to addre ss this question.

Attachment O, EPA Region IX Q&A, at 8 of 11. In a phone call on January 22, 2013, AEPCO committed to working with EPA Region IX and ADEQ to resolve this issue. AEPCO is including this issue in the petition for administra tive reconsideration to allow that resolution to be formalized, if necessary, and to clarify th e status of ST1, GT1 and their joint exhaust operation, sometimes called CC1.

AEPCO requests clarification from EPA, and, by copy of this petiti on, from ADEQ, that for purposes of the Regional Haze BART SIP and FIP, emissions from ST1 and GT1 should be

handled as follows:

 Emissions from ST1 running in “stand-alone ” mode using LNB and existing or upgraded FGR capacity (not including GT1 exhaust), must meet the SIP limits.

 Emissions from ST1 running with GT1, wher e GT1 emissions are either ducted to the windbox (formerly called “combined cycle” mode) or used to provide FGR support, must

meet the SIP limits.

 Emissions from GT1 running in “stand-al one” mode (e.g., where emissions are ducted through the GT1 stack and not into ST1) are exempt from BART.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 20

AEPCO believes that this approach best resolves the problems caused by the dual nature of GT1, treating it as part of a combined cycle unit when exhausti ng through ST1, and hence subject to the ST1 BART determination, and treating it as an exempt simple cycle turbine when it is operating by itself. Part 51, App. Y, §II.A.3(1) (“Simple cycle tu rbines are not ‘steam electric plants’ because they typically do not make steam.”). GT1 can not produce steam in its standalone configuration.

III. EPA Should Reconsider the Averaging Provision

In its BART FIP, EPA established that co mpliance is determined for Apache Generating Station Units ST2 and ST3 as a 30-day rolling average across both ST2 and ST3, 40 C.F.R. § 52.145(f)(5)(ii)(A), and for ST1on a 30-day rolling average stand-alone basis, id. § 52.145(f)(5)(ii)(B). While AEPCO is appreciative of EPA’s responsiveness to the request of AUG, which requested an option for averaging, AEPCO believes that the mandatory averaging provision inappropriately and unfai rly places AEPCO at compliance risk and may also have the effect of shortening or limiting maintenance work in a way that is not consistent with good air pollution control engi neering practice.

AEPCO units ST2 and ST3 are used for load following and hence cycle. AEPCO unit ST1 is used primarily for peaking. Because thes e units are subject to fluctuating loads, the ability of the units to continuous ly achieve the stringent NOx limits prescribed, particularly on a 30-day rolling average basis. Particularly fo r ST2 and ST3, AEPCO is concerned that one unit may trip out and then have a poor restart follo wed by another trip out, causing the average to

exceed the limit. This causes se veral quandaries: (1) restart of th e unit is necessary to lower the average back into compliance; but (2) restart of th e unit will, temporarily at least, exacerbate the exceedance. Because the out-of-service unit pounds of NOx are counted against the in-service unit, it creates an incentive to hurry maintenance to bring the unit back on -line. This may cause additional trips as restart is hur ried. AEPCO is not certain that EPA intended this result.

AEPCO also believes that it is inequitable to penalize it for taking a unit that is having

trouble down for maintenance. In such a situation, AEPCO w ould be doing everything in its power to reduce emissions (e.g., it has shut down the unit with excess emi ssions). Nevertheless, AEPCO would, under the rule, conti nue to accrue penalties until such time as AEPCO was able to restart the unit and bring its emissions dow n (or reduce emissions on the other unit by an offsetting amount). AEPCO believes it is inequitable to be penalized for days of violation if the sole operating unit is meeting the effective equivalent of the 0.07 lb NOx/MMBtu limit.

AEPCO respectfully requests that EPA consider this issue and work with AEPCO and the other affected utilities to develop an appropriate response in the FIP.

IV. Alternative Approaches to Visibility Improvement

AEPCO understands that the Clean Air Act re quires that BART be installed and that progress be made toward achievi ng the national visibility goal in Section 169A of the Act.Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 21

Nevertheless, Congress wanted this goal to be achieved in a co st-effective way and in a manner that does not frustrate the goals of the Rural El ectrification Act to provide reasonably priced power to the rural areas of the United States, including those rural areas which AEPCO and its

members serve.

AEPCO is willing to consider potential al ternatives to LNB + OFA + SCR. AEPCO believes that alternative appro aches could achieve much of EP A’s visibility objectives while reducing the costs to AEPCO and its members so that the economic viability of the Apache Station is not jeopardized. Su ch alternative approaches could also provide AEPCO sufficient time to plan for the financing and rate impacts.

Request for Administrative Stay

EPA has authority under the Administra tive Procedure Act (“APA”) Section 705, 5 U.S.C. § 705, and the Clean Air Act (“CAA”) S ection 307, 42 U.S.C. § 7607, to grant a stay while the rule is being reconsid ered. APA Section 705 provides in relevant part that “[w]hen an agency finds that justice so re quires, it may postpone the effec tive date of action taken by it, pending judicial review.” 5 U.S.C. § 705. The additional showing of “prevent[ing] irreparable injury” is a requirement only for a reviewing court, not the agency. Id . CAA Section 307(d)(7)(b) additionally provides th at, “[t]he effectiveness of th e rule may be stayed during such reconsideration, however, by the Administrato r or the court for a pe riod not to exceed three months.” 42 U.S.C. § 7607(d)(7)(b).

EPA’s only precondition for granting a stay is when “justice so requires” under the APA

and to have commenced reconsideration under CAA Section 307. EPA is not required to review a request for stay under the same strict guidelines the statutes impose on th e courts, and can grant a stay more readily, as the standard under the APA and CAA does not require petitioner to show irreparable harm prior to the grant of the stay.

As explained herein, justice does requir e EPA to grant a stay and AEPCO will face irreparable harm if it is not granted. First, just ice requires that EPA stay the rule. The process by which EPA promulgated the rule did not take into account information vital to AEPCO, including cost and market data that AEPCO, as a small entity, could not develop in time to submit during the comment period. These data, presented above, show the substantial and ultimately unsustainable impact of the rule on AEPCO. AEPCO also did not know, and could not have known, that EPA would consider its Ga s Turbine 1 simple-cycle operations would be considered part of the BART determination, as this was first stated by EPA in response to questions after the rule was finalized. Finally, AEPCO did not have an opportunity to review and comment on the promulgated aver aging approach in the rule.

Additionally, a number of parties have al ready, or will, cha llenge the rule both administratively through petitions for reconsider ation and through judicial review in the NinthPetition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 23

Patrick Ledger, AEPCO (w/o enclosures) Dwight M. Whitley, Jr., AEPCO (w/o enclosures) Michelle Freeark, AEPCO (w/enclosures)Petition for Administra tive Reconsideration Arizona Electric Power Cooperative, Inc. February 2, 2013 Page 24

APPENDIX

LIST OF ATTACHMENTS

A. AEPCO Bylaws, Section 7.02

B. Rate Schedule A and Exhibits and Attachments C. Affidavit of Gary E. Pierson, Manager of Financial Services, Ar izona Electric Power Cooperative, Inc. [Confidential Busi ness Information – Not Supplied] D. AEPCO Energy Information Ad ministration (EIA) Form 890 Report E. AEPCO Generator Summary Reports, 2004- 2011 [Confidential Bu siness Information – Not Supplied] F. Declaration of Richard E. Stinneford, Managing Member, Washington Utility Group,

LLC G. Affidavit of Richard P. Kurtz, Vice Pres ident of Power Services and Planning, Arizona Electric Power Cooperative, In c. [Confidential Business Information – Not Supplied] H. Affidavit of Walter T. Bray, Director of Energy Services, Arizona Electric Power Cooperative, Inc. [Confidential Busi ness Information – Not Supplied] I. Affidavit of Barry A. Brown, Director of Engineer, Arizona Elect ric Power Cooperative, Inc. [Confidential Business Information – Not Supplied] J. Affidavit of Peter F. Scott, Chief Fina ncial Officer, Arizona El ectric Power Cooperative,

Inc.

K. LNB + OFA + SCR Installation Costs and Justification

L. SO 2 Scrubber Upgrade Costs and Justification M. Arizona Electric Power Cooperative, In c., 2013 Financial Forecast, EPA Case with 1.32 DSC (the “Revised Financial Forecast”) N. EPA Clean Air Marketing Di vision correspondence regarding ST1 O. EPA Region 9, BART Q&A document P. Affidavit of J. Tyler Carlson, Chief Execu tive Officer, Mohave Electric Cooperative, Inc. [Confidential Business Info rmation – Not Supplied] Q. Affidavit of Creden W. Huber, Chief Ex ecutive Officer, Sulphur Springs Valley Electric Cooperative, Inc. [Confidential Busi ness Information – Not Supplied] R. Affidavit of Vincent Nitido, Chief Executiv e Officer/General Mana ger, Trico Electric Cooperative. [Confidential Busine ss Information – Not Supplied]